Pipelines for the transport of hydrocarbons, e.g. oil or gas, are typically laid along the seabed using a laying vessel. Such subsea pipelines can be installed between, for example, two subsea structures, where the subsea structures may be “Christmas trees”, riser bases, Blowout Preventers (BOPs), or some other structures. Often one or both ends of the pipeline are connected (or “tied-in”) to a subsea structure using a separate jumper or spool. The extra components and procedures associated with the use of separate jumpers or spools result in high costs for the installation process. Direct tie-in methods can also be used and are often preferable. These methods include:                direct pull-in, in which an end of the pipeline is pulled close to the subsea structure using a winch location on the laying vessel, and the tie-in is completed using a remotely operated vehicle (ROV) and alignment apparatus;        deflect to connect, in which a wire is attached to the end of the pipeline, where the wire is routed through the subsea structure to a winch, and the wire is used to pull the subsea end of the pipeline directly to the subsea structure; and        connect and lay-away, in which the subsea end of the pipeline is connected to the subsea structure at the surface, and the subsea structure is then lowered to the seabed before the laying vessel lays the pipeline by stepping away from the subsea structure.        
During tie-in to a sub-sea structure, significant forces will be required to move an as-laid pipeline axially towards the connection point due to parameters such as pipeline axial stiffness, submerged weight, seabed friction resistance etc. Thus, the main challenges for conventional direct tie-in methods are relatively large forces on the connection and large pipeline stresses close to the connection point.
A typical approach to pipe laying will involve careful design of the subsea structure and of the pipeline configuration in order to ensure that, when laid, the tie-in end of the pipeline is in the correct location and orientation with respect to the connector on the subsea structure. During the direct tie-in process, a very high tensile force is applied to the end of the pipeline, putting the pipeline under tension, in order to bring the end of the pipeline up to the connection point and complete the tie-in process. One of the reasons to put the installed pipe under tension is in order to allow for subsequent thermal expansion of the pipe that can occur during use. Without such tension, a pipeline may buckle as a result of the thermal expansion.
The forces applied to the pipeline during direct tie-in can be very high indeed. This makes high demands of the installation equipment and pipeline structure. Furthermore, at least in the absence of some compensating mechanism, the forces can cause damage to the pipeline and to the connector on the subsea structure.
In co-pending application WO-A-2015/149843 to the present applicant, is disclosed a method of installing a subsea pipeline having a direct tie-in to a subsea structure. The method comprises, during introduction of the pipeline into the sea from a pipe laying vessel, applying a plastic deformation to a region of the pipeline at or close to an end of the pipeline to be tied-in and, either during or following tie-in, elastically deforming said region to increase its radius of curvature.
A pipeline to be laid on the seabed may be transported on and deployed from a laying vessel. In the case that a substantially inflexible pipeline (for example, steel) is stored on a reel on the laying vessel, it is typically necessary to straighten the pipeline as it is deployed, to remove any residual curvature produced by storing the pipeline on the reel or bending it over the stinger. This is achieved using curvature means that plastically deforms the pipeline to remove the residual curvature.
As described above, the installation of such straightened pipelines using direct tie-in methods can result in large forces during and following the completion of the connection between an end of a pipeline and a subsea structure, and large stresses in the section of the pipeline near the end of the pipeline. Furthermore, a large area is required for routing the pipeline to the subsea structure, to accommodate the lateral deflection of the pipeline required to align the end of the pipeline with a connection point on the subsea structure. The approach presented in WO-A-2015/149843 mitigates these problems by using the method of WO-A-02/057674 to create a radius of curvature in a section of the pipeline adjacent to the subsea end of the pipeline (creating a “tie-in and thermal expansion loop”).
Local residual curvature may also be generated with S-lay vessels during installation, by 1) adjusting roller(s) or 2) by adjusting the stinger configuration with the pipeline in place. Generation of local residual curvature may also be feasible on other S-lay barges by modification to one or two of the stinger rollers, enabling adjustment whilst laying.
In operation, a pipeline will expand under the high pressures and temperatures that can be associated with the transport of, for example, oil or gas. In the case of a generally straight configuration between, for example, two subsea structures that are fixed on the seabed, such thermal expansion (which will result in an increased pipeline length) will result in compressive forces on the pipeline. These compressive forces may be significant and, in the absence of some control mechanism, can cause the pipeline to buckle at unpredictable locations, resulting in the deformation and possible collapse of the pipeline in the horizontal or vertical plane.
In conventional installation methods the pipeline is placed under tension as it is deployed from the laying vessel, due to both the weight of the pipe itself and the forward motion of the laying vessel. This tensile force results in an axial elastic extension in the pipeline, and because the pipeline does not regain its original length before the installation process is complete, the installed pipeline remains under tension. This pre-existing tension in the pipeline mitigates the effects of the longitudinal expansion in the operational pipeline; however, the resulting compression forces may still be large enough to cause buckling. Further measures that are commonly used to protect against the buckling of a pipeline include burying the pipeline in a trench or placing it in an open trench, covering the pipeline with gravel, laying the pipeline along a snaked route, laying the pipeline in a larger casing, and including expansion loops in the pipeline along its length. These methods may be expensive, and may leave uncertainty regarding the likelihood and possible location of buckling in the pipeline.
In FIG. 1 a first end tie-in procedure is illustrated: the pipeline 1 can be initiated against a return sheave arrangement 100 on the subsea structure 5 and lowered/docked in a controlled manner onto a guide post/landing frame etc. depending on the tie-in system being employed. The initiation wire 7 extends from the pipeline end terminal (PLET) 101, through the sheave arrangement 100 and back to a winch (not shown) on the lay vessel. The lay vessel is also not shown for clarity.
When the end of the pipeline 1 is close enough to the subsea structure 5, the final stages of the direct tie-in process are completed using a remotely operated vehicle (ROV) 9. In this case ROV 9 is provided from an installation vessel, but the ROV could also be associated with the laying vessel.
A residual curvature section 102 is shown introduced approximately 100 m away from the pipeline end. A wire tensioning system 103 using a standard torque tool is considered to be an efficient method if it is necessary to retract the pipeline end 101 in a controlled manner and to maintain a stable pre-bent section.
Hub capacity is often seen to be a governing factor for pipeline tie-ins using diverless systems. Since hubs on subsea templates typically could be elevated 2.5 m above the seabed floor, vertical alignment between pipeline end and the hub is a key parameter. In order to compensate for this, the hub can typically be tilted slightly downwards, say 3°, 5° or 7°. However, further vertical alignment will in many cases be needed. This has on several projects been solved by introducing rock supports 104 or adjustable mechanical supports in the adjacent free span. After the pipeline is pulled down and safely landed in the tie-in porch/landing frame, the pipeline is ready for the final stroke-in and finally the clamp connector is made up and the seal can be tested. The new generation tie-in systems HCCS, HCS and UCON, are based on landing the termination head into the porch, letting the ROV stroke the hubs together by the temporary stroking tool and engage the connector.
Since in prior techniques the pipeline typically will have to be laid adjacent to the subsea structure, after which a lift- and shift operation of the pipeline is required, with proper adjustment of the axial lay tolerance, prior to the tie-in/connection operation. The lift and shift operation normally has to be performed after water filling the pipeline, and after removal of a temporary pig trap. Some additional vessel time is required to do this work, prior to the actual tie-in/connection operation.